In the production of oil from subterranean formations, it is usually possible to recover only a small fraction of the total oil present in the formation by so-called primary recovery methods which utilize only the natural forces present in the reservoir. To recover oil beyond that which is produced by primary methods, a variety of supplemental production techniques have been employed. Secondary recovery methods rely on the supply of external energy in the form of injecting fluids to increase reservoir pressure, hence replacing or increasing the natural reservoir drive with an artificial drive. Waterflooding, via the injection of water or brine into the reservoir, is another common oil recovery method.
In the use of flooding techniques, various polymeric thickening agents have been added to the drive fluid to increase its viscosity to a point where it approaches that of the oil which is to be displaced, thus improving displacement of oil from the formation. Conventional polymer waterflooding typically utilizes a synthetic polymer, such as partially hydrolyzed polyacrylamide (“PHPA”), or a biopolymer, such as xanthan gum. However, significant viscosity loss due to shear damage and chemical degradation can affect the oil displacement efficiency in such polymer flooding operations.
The third phase of oil extraction during the lifetime of a reservoir is called tertiary recovery, or Enhanced Oil Recovery (“EOR”). Commonly, this involves injection of chemicals into the reservoir to liberate oil from rock (i.e., microscopic displacement efficiency) or polymers to improve the efficiency at which oil is pushed through the formation (i.e., macroscopic sweep efficiency). One common EOR technology is the injection of polymer to mitigate the problem of excess water production. In a process called profile modification or permeability modification, polymer gels are injected near wellbore or in-depth to preferentially seal fractures or high permeability zones, commonly called thief zones. Permeability reduction or pore blocking results from polymer adsorption in such high permeability zones. As a result of this process, subsequently injected fluids are redirected to lower permeability, unswept oil-rich zones, leading to additional oil production and reduced water-cut.
Most crosslinked polymer gel water shut-off treatments practiced today use ready-made polymers that become crosslinked and gel in the formation. One common gel system that has been extensively investigated uses PHPA or acrylamide/acrylate copolymers as the polymer component. M. Kelland, CHEMICALS FOR THE OIL & GAS INDUSTRY, Chapter 2 (2nd ed., 2014). The crosslinking agent can be an inorganic compound, typically containing chromium, aluminum, titanium, or zirconium ions. However, metallic crosslinking of carboxylate polymers such as PHPA is generally not suitable for high temperature applications. In high temperature reservoirs, excessive polymer hydrolysis can occur, resulting in syneresis via additional unwanted crosslinking between the polymer and excess crosslinker and divalent cations such as magnesium and calcium.
Delayed gel systems based on organic crosslinking of acrylamide, acrylic esters, and co-polymers thereof, have also been developed. These typically utilize dialdehydes, polyethyleneimine, or mixtures of phenolic compounds and an aldehyde as the crosslinking agent. Overall, in situ preparation of such crosslinked polymer gels have been disadvantaged by a number of factors, including high viscosity of the bulk chemical solution, uncontrolled gelation times and variations in gelation due to shear degradation, thermal instability of the gel, and sensitivity to reservoir minerals and formation water salinity. Thus, polymer gels widely used for near wellbore conformance control applications may not be effective for in-depth fluid diversion.
As an alternative to in-situ gelation treatments for in-depth fluid diversion, a newer trend is the use of preformed gels. Bai, B., “Preformed Particle Gel for Conformance Control,” Paper presented at 6th International Conference on Production Optimization—Reservoir Conformance—Profile Control—Water/Gas Shut-Off—Houston, Tex., Nov. 6-7, 2007. In preformed gel systems, the gel is formed in surface facilities and then gel is injected into the reservoir. Preformed gel systems include preformed bulk gels, partially preformed gels, preformed particle gels, microgels (U.S. Pat. No. 6,579,909), pH sensitive crosslinked polymer, millimeter-sized swelling polymer grains, and Brightwater® microparticles (U.S. Pat. No. 6,984,705).
Weak gel technologies address the practical limitations associated with conventional polymer flooding operations and conformance control operations. Weak gels are crosslinked polymers formed in situ that have higher viscosity than conventional uncrosslinked polymer floods, enabling them to act as mobility control agents. In addition, weak gels can be used to address the problem of fluid channeling by “plugging” high permeability or thief zones, and diverting trailing fluid flow to adjacent poorly swept areas of the reservoir. Thus, weak gels can be used as conformance control agents. However, unlike traditional conformance control agents prepared as in situ gels, weak gels can more effectively be used to achieve in-depth fluid profile control. When the gelant is injected into a reservoir, a crosslinking reaction occurs in situ near the wellbore region but continue to propagate into the reservoir, preferentially penetrating more into high permeability zones than into low permeability zones. In the subsequent waterflood or chemical flood, the weak gel system may be gradually pushed deeper into the formation. In this process, the weak gel is pushed or squeezed into fine particles through the porous formations. When these particles migrate into pore throats, some of them squeeze, deform and pass through the throats propagating forward, while others are trapped at the pore throats effectively blocking high permeability zones. Thus, successful weak gel system applications improve the injection profile and balance the fluid distribution to enhance reservoir recovery, including both the areal sweep efficiency and vertical sweep efficiency. Furthermore, as the weak gel migrates slowly through the high permeability zones, it pushes forward banking oil droplets at the displacing front so that the residual oil in the high permeability zones is mobilized and recovered. Han et al., State-of-the-Art of In-Depth Fluid Diversion Technology: Enhancing Reservoir Oil Recovery by Gel Treatments, Paper presented at Society of Petroleum Engineers Saudi Arabia Section Technical Symposium and Exhibition, Al-Khobar, Saudi Arabia, SPE-172186-MS (Apr. 21-24, 2014).
Despite the knowledge of weak gels having utility in oilfield applications, a need remains for in-situ weak gels having satisfactory performance properties under a broad range of subterranean conditions.